IR 05000348/2006002
| ML061180072 | |
| Person / Time | |
|---|---|
| Site: | Farley, 07200042  |
| Issue date: | 04/28/2006 |
| From: | Scott Shaeffer NRC/RGN-II/DRP/RPB2 |
| To: | Stinson L Southern Nuclear Operating Co |
| References | |
| IR-06-002 | |
| Download: ML061180072 (20) | |
Text
April 28, 2006Southern Nuclear Operating Company, Inc.ATTN: Mr. L. Vice President - Farley ProjectP. O. Box 1295 Birmingham, AL 35201-1295SUBJECT:JOSEPH M. FARLEY NUCLEAR PLANT - NRC INTEGRATED INSPECTIONREPORT 05000348/2006002 AND 05000364/2006002
Dear Mr. Stinson:
On March 31, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an inspectionat your Joseph M. Farley Nuclear Plant, Units 1 and 2. The enclosed integrated inspection report documents the inspection findings, which were discussed on April 6, 2006, with Mr.
Randy Johnson and other members of your staff.The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.Based on the results of this inspection, one NRC-identified finding of very low safetysignificance was identified and determined to be a violation of NRC requirements. Because thisviolation is of very low safety significance and was entered into your corrective action program, the NRC is treating this violation as a non-cited violation (NCV) consistent with Section VI.A ofthe NRC Enforcement Policy. If you contest this NCV, you should provide a response within 30days of the date of this inspection report, with the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRCResident Inspector at the Farley Nuclear Plant.In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, itsenclosures, and your response (if any) will be available electronically for public inspection in the SNC2NRC Public Document Room or from the Publicly Available Records (PARS) component of theNRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/Scott M. Shaeffer, Acting ChiefReactor Projects Branch 2 Division of Reactor ProjectsDocket Nos. 50-348, 50-364, and 72-42License Nos. NPF-2 and NPF-8
Enclosure:
Inspection Report 05000348/2006002 and 05000364/2006002 w/Attachment: Supplemental Information
REGION IIDocket Nos.:50-348, 50-364, 72-42License Nos.:NPF-2, NPF-8 Report Nos.:05000348/2006002 and 05000364/2006002 Licensee:Southern Nuclear Operating Company, Inc.
Facility:Joseph M. Farley Nuclear PlantLocation:7388 N. State Highway 95Columbia, AL 36319Dates:January 1- March 31, 2006 Inspectors:C. Patterson, Senior (Sr.) Resident InspectorJ. Baptist, Resident Inspector R. Taylor, Reactor InspectorApproved by:Scott M Shaeffer, Acting ChiefReactor Projects Branch 2 Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
IR 05000348/2006002 and 05000364/2006002; 01/01/2006-03/31/2006; Joseph M. Farley NuclearPlant, Units 1 & 2.The report covered a three-month period of inspection by the resident inspectors and a regional reactorinspector. One Green non-cited violation was identified. The significance of most findings is indicated by its color (Green, White, Yellow, or Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after management review. The NRC's program for overseeing the safeoperation of commercial nuclear power reactors is described in NUREG-1649, Reactor OversightProcess, Revision 3, dated July, 2000.A.
NRC-Identified and Self-Revealing Findings
Cornerstone: Mitigating SystemsA
Green, NRC-identified, non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XIV,Corrective Actions, was identified for failure to promptly identify and correct a failure of the 1F (Unit 1 Train A Engineered Safety Feature) 4-kV bus synchroscope resulting in the unrecognized inoperability of the 1-2A Emergency Diesel Generator (EDG) set.This finding is more than minor because it is associated with the Equipment Performanceattribute of the Mitigating Systems cornerstone and because it affects the associated cornerstone objective. Specifically, the Mitigating System Cornerstone objective is to ensure availability, reliability, and capability of systems that respond to initiating events to preventundesirable consequences in the future. This finding is of very low safety significance (Green) because there was no complete loss of system safety function and no direct effect oninitial accident response or system mission time. This finding involved the cross-cuttingaspect of Identification within the area of Problem Identification and Resolution due to cognitive personnel error and knowledge deficiency, in that, it was unclear to the operating crew that loss of the voltmeter indicated that the synchroscope might also be inoperable.
B. Licensee-Identified Violations
None 3Enclosure Enclosure
REPORT DETAILS
Summary of Plant StatusUnit 1 operated at or near rated thermal power (RTP) until March 1, 2006 when power was reduced to20 percent to add oil to the 1C Reactor Coolant Pump (RCP). The unit returned to full power on March
4, 2006.Unit 2 operated at or near RTP during the entire report period.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity1R04Equipment Alignmenta.Inspection ScopePartial System Walkdowns. The inspectors performed partial walkdowns of the following threesystems to verify they were properly aligned when redundant systems or trains were out ofservice. The walkdowns were performed using the criteria in licensee procedures FNP-0-AP-16, Conduct of Operations - Operations Group, and FNP-0-SOP-0, GeneralInstructions to Operations Personnel. Walkdown preparations included reviewing the Updated Final Safety Analysis Report (UFSAR), plant procedures and drawings, checks of control roomand plant valves, switches, components, electrical power line-ups, support equipment, and instrumentation.The 1-2A Emergency Diesel Generator (EDG) while the 1B EDG was having maintenanceperformedThe 1A Containment Spray (CS) pump train during a 1B CS pump equipment outageThe 1A Residual Heat Removal (RHR) pump during 2A RHR pump equipment outageb.FindingsNo findings of significance were identified.
1R05 Fire Protectiona.Inspection ScopeFire Area Tours
The inspectors conducted walkdowns of the ten fire areas listed to verify thelicensee's control of transient combustibles; the operational readiness of the fire suppression system; and the material condition and status of fire dampers, doors, and barriers. Therequirements were described in licensee procedures FNP-0-AP-36, Fire Surveillance andInspection; FNP-0-AP-38, Use of Open Flame; FNP-0-AP-39, Fire Patrols and Watches; and the associated Fire Zone Data sheets.Unit 1 Auxiliary Building 121' 4160-V Train B Switchgear Room Area, Fire Zone 21 4EnclosureUnit 1 Auxiliary Building 121' Control Rod Drive Mechanism (CRDM) Control System CabinetRoom, Fire Zone 23Unit 1 Auxiliary Building 121' 4160-V Load Center Cooling Unit Corridor, Fire Zone 20Unit 1 Auxiliary Building 139' 4160-V Train A Switchgear Room Area, Fire Zone 41Unit 1 Auxiliary Building 139' Load Center 1D A/C Unit Corridor, Fire Zone 42Unit 2 Auxiliary Building 121' 4160-V Train B Switchgear Room Area, Fire Zone 21Unit 2 Auxiliary Building 121' CRDM Control System Cabinet Room, Fire Z one 23Unit 2 Auxiliary Building 121' 4160-V Load Center Cooling Unit Corridor, Fire Zone 20Unit 2 Auxiliary Building 139' 4160-V Train A Switchgear Room Area, Fire Zone 41Unit 2 Auxiliary Building 139' Load Center 2D A/C Unit Corridor, Fire Zone 42b.FindingsNo findings of significance were identified.
1R07 Heat Sink PerformanceBiennial Inspectiona. Inspection ScopeThe inspectors reviewed inspection records, test results, maintenance work orders, and otherdocumentation to ensure that heat exchanger (HX) deficiencies that could mask or degradeperformance were identified and corrected.
Risk significant heat exchangers reviewed included the Component Cooling Water (CCW) HXs along with the EDG jacket water HXs.The inspectors reviewed completed HX inspection and cleaning procedures, inspectionfrequency, and tube plugging maps. In addition, the inspectors reviewed eddy current test reports for the selected HXs. The inspectors reviewed these documents of selected HXs to determine if the heat exchanger test methodology was consistent with licensee commitmentswith respect to NRC Generic Letter 89-13, Service Water System Problems AffectingSafety-Related Equipment commitments; test conditions were appropriately considered; test or inspection criteria were appropriate and met the acceptance criteria; the test frequency was appropriate; as-found conditions were appropriately dispositioned such that the final condition was acceptable; and test results considered test instrument inaccuracies and differences.The inspectors also reviewed the overall condition of the Service Water (SW) system via reviewof design basis documents, system health reports, and discussions wit h the SW systemengineer. These documents were reviewed to verify that the design basis was being maintained and to verify adequate SW system performance under current preventivemaintenance, inspections and frequencies. The inspectors also walked down the SW intake structure and observed a chemical treatment to the SW back up to auxiliary feedwater.Condition Evaluation Reports (CERs) were reviewed for potential common cause problems andproblems which could affect system performance to confirm that the licensee was entering problems into the corrective action program and initiating appropriate corrective actions. In 5Enclosureaddition, the inspectors conducted a walkdown of selected HXs and major components for theSW system to assess general material condition and to identify any degraded conditions.b.FindingsNo findings of significance were identified.
1R11 Licensed Operator Requalificationa.Inspection ScopeThe inspectors observed portions of the licensed operator training and testing program to verifyimplementation of procedures FNP-0-AP-45, Farley Nuclear Plant Training Program; FNP-0-
TCP-17.6, Simulator Training Evaluation Documentation; and FNP-0-TCP-17.3, LicensedOperator Continuing Training Program. The inspectors observed scenarios conducted in the licensee's simulator for a loss of feedwater, loss of heat sink, loss of core cooling, and failure to trip. The inspectors observed high-risk operator actions, overall performance, self-critiques, training feedback, and management oversight to verify that operator performance was evaluated against the performance standards of the licensee's scenario. In addition, the inspectors observed implementation of the applicable emergency operating procedures listed in the Attachment to verify that licensee expectations in procedures FNP-0-AP-16 and FNP-0-TCP-17.6 were met.b.FindingsNo findings of significance were identified.
1R12 Maintenance Effectivenessa.Inspection ScopeThe inspectors reviewed the following two issues to verify implementation of licenseeprocedures FNP-0-87, Maintenance Rule (MR) Scoping Manual; NMP-ES-021, Structural
Monitoring Program for the Maintenance Rule; FNP-0-89, FNP Maintenance Rule Site Implementation Manual; and compliance with 10CFR50.65. The inspectors assessed the licensee's evaluation of appropriate work practices, common cause failures, functional failures, maintenance preventable functional failures, repetitive failures, availability and reliabilitymonitoring, trending and condition monitoring, and system specialist involvement. Theinspectors also interviewed maintenance personnel, system specialists, the MR coordinator,and operations personnel to assess their knowledge of the program.Condition Report (CR) 2006101422, Nuclear Instrumentation System Source Range FailuresCR 2006100937, Unit 1 Radiation Monitoring Detector R-19 Corrective Actionsb.FindingsNo findings of significance were identified.
6Enclosure1R13Maintenance Risk Assessments and Emergent Work Controla.Inspection ScopeThe inspectors assessed the licensee's planning and control for the five listed planned activitiesto verify that the requirements in licensee procedures FNP-0-ACP-52.3, Guidelines for Scheduling of On-Line Maintenance; NMP-GM-006, Work Management; and FNP-0-AP-16, Conduct of Operations - Operations Group; and the MR risk assessment guidance in10CFR50.65a(4) were met.Risk Evaluation associated with 1A CS Pump Outage on January 27, 2006CR 2006100908, Service Water (SW) Structure Fire Main Clapper Actuation Flooding CR 2005112444, 2A Motor-Driven Auxiliary Feedwater (MDAFW) Inadvertent Start CR 2006101709, 1C EDG Remote Shutdown Electronic Governor TroubleshootingCR 2006102210, Unit 1 Solid State Protection System (SSPS) Testing Postponed Due toExciter Cooler Leakageb.Findings1R14Personnel Performance During Non-Routine Plant Evolutions and Eventsa. Inspection ScopeThe inspectors reviewed one Unit 1 event. On March 1, 2006, the inspectors observed a Unit 1planned down-power to resolve an issue with the 1C RCP Lower Motor Oil Reservoir Level Low indication. The unit was reduced to 20 percent reactor power to accommodate containment entry and associated maintenance activities to investigate the oil loss and refill the respective oilreservoir. The plant was restored to 100 percent reactor power on March 4, 2006, after appropriate repairs were completed. For a non-routine plant event, the inspectors assessed the licensee's use of operating procedures, annunciator procedures, abnormal operating procedures, control room actions, command and control, management involvement, training expectations, previous CRs, maintenance work history, and communication. The inspectors reviewed operator logs, plant computer data, control room strip charts, and discussed actions with operations personnel. Documents reviewed are listed in the Attachment.b.FindingsNo findings of significance were identified.
1R15 Operability Evaluationsa.Inspection ScopeThe inspectors reviewed the five listed operability evaluations to verify they met therequirements of licensee procedures FNP-0-AP-16, Conduct of Operations and
7EnclosureFNP-0-ACP-9.2, Operability Determination, for technical adequacy, consideration of degradedconditions, and identification of compensatory measures. The inspectors reviewed the evaluations against the design bases, as stated in the UFSAR and Functional System Descriptions (FSDs) to verify that system operability was not affected.CR 2006101160, 2D SW Pump Failure to StartCR 2006100068, 1C EDG Governor Speed Setter Found in Wrong PositionCR 2005113029, 2A Coolant Charging Pump Gas Accumulation IssueCR 2005112444, 2A MDAFW Pump Inadvertent StartCR 2006101974, PT485 2B Steam Generator Pressure Erratic Indicationb.FindingsNo findings of significance were identified.
1R19 Post-Maintenance Testinga.Inspection ScopeThe inspectors reviewed the criteria contained in licensee procedures FNP-0-PMT-0.0, Post-Maintenance Test Program, to verify that post-maintenance test procedures and test activities
for the following five systems/components were adequate to assure system operability andfunctional capability.FNP-2-STP-22.2, 2B AFW Pump Quarterly Inservice TestFNP-1-STP-16.1, 1A Containment Spray Pump Quarterly Inservice TestFNP-2-STP-4.2, 2B Coolant Charging Pump Quarterly Inservice TestFNP-2-STP-24.2, 2D SW Pump Quarterly Inservice TestFNP-1-STP-80.23, EDG 1C Remote Shutdown Capability Testb.FindingsNo findings of significance were identified.
1R22 Surveillance Testinga.Inspection ScopeThe inspectors reviewed surveillance test procedures and either witnessed the test or reviewedtest records for the six listed surveillance tests to determine if the tests adequately
demonstrated equipment operability and met the TS requirements. The inspectors reviewedthe activities to assess for preconditioning of equipment, procedure adherence, and valve alignment following completion of the surveillance. The inspectors reviewed licensee procedures FNP-0-AP-24, Test Control; FNP-0--050, Master List of SurveillanceRequirements; and FNP-0-AP-16, Conduct of Operations, and attended selected briefings to determine if procedure requirements were met.
8EnclosureSurveillance TestsFNP-2-STP-4440, Steam Generator Water Level Control TestFNP-1-STP-114.1, Moderator Temperature Coefficient Determination for C B 300ppmFNP-1-STP-16.12A, 1A CS Pump Automatic Starting Circuitry TestFNP-1-STP-33.2B, Reactor Trip Breaker Train B Operability TestIn-Service Tests (ISTs)FNP-1-STP-11.1, 1A RHR Pump Quarterly Inservice TestReactor Coolant System (RCS) Leak DetectionFNP-1-STP-9.0, RCS Leakageb.FindingsNo findings of significance were identified.4.OTHER ACTIVITIES 4OA1Performance Indicator Verificationa.Inspection ScopeThe inspectors sampled licensee submittals for the performance indicators (PIs) listed below toverify the accuracy of the data reported. The PI definitions and the guidance contained in NEI99-02, Regulatory Assessment Performance Indicator Guideline, Revision 2, and licensee procedure FNP-0-AP-54, Preparation and Review of NRC Performance Indicator Data, wereused to verify that procedure and reporting requirements were met.Mitigating Systems Cornerstone*Unplanned Scrams*Scrams with Loss of Normal Heat Removal
- Unplanned Power ChangesThe inspectors reviewed samples of raw PI data, Licensee Event Reports (LERs), and MonthlyOperating Reports for the period covering January 2004 through December 2005. The data reviewed from the LERs and Monthly Operating Reports was compared to graphical representations from the most recent PI report. The inspectors also examined a sampling of operations logs and procedures to verify that the PI data was appropriately captured for inclusion into the PI report as well as ensuring that the individual PIs were calculated correctly.
The inspectors identified an omission of data for Unit 2 Unplanned Power Changes in the second quarter of 2004. This would have changed the indicated value from this quarter until the second quarter of 2005, but would not have caused the PI to cross the White threshold. The error was addressed by the licensee in CR 2006102114.b.FindingsNo findings of significance were identified.
9Enclosure4OA2Identification and Resolution of Problems.1Daily Review As required by Inspection Procedure 71152, Identification and Resolution of Problems, and tohelp identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensee's corrective action program. This review was accomplished by reviewing daily hard copy summaries of CRs and by reviewing the licensee's electronic CR database..2Annual Sample Review
a. Inspection Scope
As required by Inspection Procedure 71152, Identification and Resolution of Problems, the inspectors performed a detailed review of the history of problems with CR 2006100068 concerning the improper placement of the 1C EDG Governor Speed setting. The CR was examined to verify that safety concerns were properly classified and prioritized for resolution; technical issues were evaluated and dispositioned to address operability and reportability;apparent cause determinations were sufficiently thorough; extent of condition, genericimplications, common causes, and previous history were adequately considered; and appropriate corrective actions (short- and long-term) were implemented or planned in a mannerconsistent with safety and compliance. The inspectors also evaluated the CR against the requirements of the licensee's corrective action program as delineated in Procedure NMP-GM-003, Corrective Action Program, and 10 CFR 50, Appendix B.b.Findings and ObservationsNo findings of significance were identified. During Job Performance Measures (JPM) trainingon January 4, 2006, the crew observed that the speed setting on the 1C Diesel governorappeared to be 18.9 versus the required setting of 19.9. The setting was confirmed to be incorrect and was reset to the correct value of 19.9. The shift determined that the most probable cause of the incorrect setting was an error made during the previous slow-speed start performed on December 26, 2005. Based on interviews with personnel involved and a review of the events, the licensee concluded that an error had been made during the December 26,2005, run because the speed control knob was adjusted to 18.9 when the procedure directed itto be set at 19.9. Another error was made at that time when the designated IndependentVerifier failed to recognize the incorrect setting.
The crew discovering the condition determined that the diesel had successfully passed the monthly surveillance with the setting at 18.9, but were unsure what affect the setting had on the2000-hour rating of the diesel. They declared the EDG inoperable and took necessary actions per the limiting condition for operation (LCO). With the mechanical governor set at 18.9, the engine would have sped up to approximately 916 RPM (the speed equivalent to 18.9) if the electrical governor failed for any reason. However, on an isochronous start, such as an loss of offsite power (LOSP), or a normal manual start, the electrical governor would control speed at 60 Hz. A mechanical governor setting of 18.9 would limit neither the ability of the engine to run 10Enclosureat 60 Hz nor the fuel rack movement in any way so that power would be limited. Therefore, thecrew concluded that there were no adverse effects on the ability of the diesel to perform itssafety-related function, including producing the 2000-hour rating power. The diesel was not inoperable because of the incorrect setting on the governor. Based on a review of the CR, discussions with engineers and plant management, and information exchanged during licensee meetings, the inspectors concluded the licensee's assessment of the identified problem and thesubsequent corrective actions were thorough and appropriate.4OA3 Event Followup.1(Closed) Licensee Event Report (LER ) 05000348/2005-002-00, Technical Specification 3.8.1Violation Due to 1F Bus Synchroscope Failurea.Inspection ScopeThe inspectors reviewed the Unit 1 LER and CR 2005111594 documenting the 1F bussynchroscope failure and subsequent inoperability of the 1-2A DG set that occurred onNovember 11, 2005. The impact of the synchroscope failure was not initially recognized and resulted in the 1-2A EDG being inoperable and, therefore, the Technical Specification-requiredactions for an inoperable EDG were not performed. The inspectors reviewed the root cause of the issue, TS and LCO applicability, relevant control room indications, and troubleshootingresults.b.FindingsIntroduction. A Green, NRC identified non-cited violation (NCV) was identified for failure topromptly identify and correct a failure of the 1F (Unit 1 Train A Engineered Safety Features)4-kV bus [EK] synchroscope resulting in the unrecognized inoperability of the 1-2A EmergencyDiesel Generator (EDG) set.Description. On November 11, 2005 at 1149, operators were taking routine bus voltagereadings. When the 1F voltmeter selector switch was operated, the voltmeter went blank. A supplemental indication that an abnormal condition existed was the de-energized status of awhite light on the Emergency Power Panel. This light was identified to be off at the same time the voltmeter lost power; however, no personnel were aware that this light indicated power available to the applicable synchroscope. The licensee did determine that an LCO existed withrespect to TS Table 3.3.5-1 Function 3 for loss of 4-kV bus degraded grid alarm capability, andthe Required Action for this condition was met. It was not recognized at that time that the synchroscope for the 1F 4-kV bus was also affected. During troubleshooting of the voltmeter on November 14, 2005 it was determined that the voltmeter was failed due to blown fuses, and that the blown fuses also disabled the synchroscope. The synchroscope is required per TS Surveillance Requirement (SR) 3.8.14 for the ability to synchronize the 1-2A Train AEmergency Diesel Generator (EDG) to an offsite source following power restoration after an LOSP. Upon recognition that the de-energized status light resulted in inoperability of the EDG,the 1-2A EDG was subsequently declared inoperable for Unit 1 only, per TS 3.8.1 on November 14, 2005 at 1647. The fuses were replaced, restoring power to the voltmeter and the synchroscope. The 1-2A EDG was declared operable on November 14, 2005, at 2200. This 11Enclosurefinding involved the cross-cutting aspect of Identification within the area of ProblemIdentification and Resolution due to cognitive personnel error and knowledge deficiency, in that, it was unclear to the operating crew that loss of the voltmeter indicated that the synchroscopemight also be inoperable.Analysis. The finding is greater than minor because it is associated with the EquipmentPerformance attribute of the Mitigating Systems cornerstone and because it affects the associated cornerstone objective. Specifically, the Mitigating System Cornerstone objective is to ensure availability, reliability, and capability of systems that respond to initiating events toprevent undesirable consequences in the future. The failure resulted in the unrecognized inoperability of the EDG for an approximate 3-day period. This finding is of very low safetysignificance (Green) because there was no complete loss of system safety function and nodirect effect on initial accident response or system mission time.
Enforcement.
10CFR50 Appendix B Criterion XIV, Corrective Action, requires that measuresbe established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material, and equipment and nonconformances are promptly identified and corrected. Contrary to the above, the impact of the 1F 4-kV bus synchroscopemalfunction was not identified for 77 hours8.912037e-4 days <br />0.0214 hours <br />1.273148e-4 weeks <br />2.92985e-5 months <br /> and repairs were not completed to restore the 1-2A EDG to operable status until 82 hours9.490741e-4 days <br />0.0228 hours <br />1.35582e-4 weeks <br />3.1201e-5 months <br /> from the initiating event. Because this failure to follow TS is of very low safety significance and has been entered into the licensee's corrective action program (CR 2005111594), this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy; NCV 05000348/2006-002-01, Failure to Promptly Identifyand Correct Conditions Resulting in the Unrecognized Inoperability of the 1-2A EmergencyDiesel Generator.4OA5Other ActivitiesReview of Institute of Nuclear Power Operations (INPO) Evaluation ReportThe inspectors reviewed the results of an INPO evaluation of licensee performance conductedduring August 2005. The report did not identify any significant licensee performance issues that had not been previously addressed and/or reviewed by the NRC.4OA6Meetings, Including Exit1.Exit Meeting SummaryOn April 6, 2006, the inspectors presented the inspection results to Mr. Randy Johnson and theother members of his staff who acknowledged the findings. The inspectors confirmed that proprietary information was not provided or examined during the inspection.2.Annual Assessment Meeting SummaryOn April 18, the NRC's Senior Resident Inspector assigned to the Farley Nuclear Plant (FNP)met with Southern Nuclear Operating Company to discuss the NRC's Reactor OversightProcess (ROP) and the NRC's annual assessment of FNP safety performance for the period of 12EnclosureJanuary 1, 2005 - December 31, 2005. The major topics addressed were: the NRC'sassessment program and the results of the FNP assessment. A listing of meeting attendees and information presented during the meeting are available from the NRC's document system(ADAMS) as accession number ML061140063. ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.htmlATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee personnel
- W. L. Bargeron, Assistant General Manager - Operations
- W. R. Bayne, Performance Analysis Supervisor
- S. H. Chestnut, Engineering Support Manager
- P. Harlos, Health Physics Manager
- L. Hogg, Security Manager
- J. Horn, Training and Emergency Preparedness Manager
- J. R. Johnson, Plant General Manager
- T. Livingston, Chemistry Manager
- B. L. Moore, Maintenance Manager
- W. D. Oldfield, Quality Assurance Supervisor
- J. Swartzwelder, Work Control Superintendent
- R. J. Vanderbye, Emergency Preparedness Coordinator
- R. Wells, Operations Manager
- T. L. Youngblood, Assistant General Manager - Plant SupportNRC pers onnel
- L. Plisco, Deputy Regional Administrator, Region ll
- J. Shea, Deputy Division Director, Division of Reactor Projects
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Closed05000348/2005-002-00LERTechnical Specification 3.8.1 Violation Due to 1F BusSynchroscope Failure (Section 4OA3)
Opened and Closed
05000348/2006-002-01NCVFailure to Promptly Identify and Correct Conditions Resulting inthe Unrecognized Inoperability of the 1-2A Emergency DieselGenerator (Section 4OA3)